Method for reducing the H2S content of an H2S-containing subterranean formation

ABSTRACT

A process to reduce the hydrogen sulfide content of a hydrogen sulfide-containing subterranean formation and of products recovered from the subterranean formation by injecting sulfur dioxide into the subterranean formation.

RELATED CASES

This application is entitled to and hereby claims the benefit of thefiling date of U.S. provisional application Ser. No. 61/198,100 entitled“Method for Reducing the H₂S-Containing Subterranean Formation” filedNov. 3, 2008 by David K. Stevens, Peter D. Clark and Justin J. A. Lamar.

FIELD OF THE INVENTION

This invention relates to a method for reducing the hydrogen sulfidecontent of a hydrogen sulfide-containing subterranean formation and offluids produced from the subterranean formation.

BACKGROUND OF THE INVENTION

In many subterranean formations which contain crude oil, hydrocarbongases and combinations thereof, the formation may contain substantialquantities of hydrogen sulfide (H₂S). This gas is considered to be aserious pollutant in crude oil, light hydrocarbon liquids andhydrocarbon gas. It is also poisonous in certain concentrations. As aresult, a continuing effort has been directed to the development ofmethods whereby the amount of H₂S produced with hydrocarbon gases,liquids and or crude oil may be reduced.

In processes such as the well-known Claus process, H₂S can be reactedwith sulfur dioxide (SO₂) for form sulfur from SO₂ and H₂S. Theformation of sulfur occurs according to reactions as set out below.

The Claus process reactions can be considered to be:

2 H₂S+3O₂→2SO₂+2H₂O  (1)

SO₂+2H₂S→3S+2H₂O  (2)

Previously, it has been proposed to dispose of liquid or gaseous SO₂ byinjection into subterranean spent formations. These formations were notconsidered to be productive of any hydrocarbon fuels or other materialsof interest. Applicants are unaware of any attempts to reduce the amountof H₂S in such formations.

In the Alberta Sulphur Research, Ltd. Quarterly Bulletin No. 121,April-June, 2002 published by Alberta Sulphur Research, Ltd., TheUniversity of Calgary, Calgary, Alberta, Canada, it was proposed that amethod for disposing of sulfur or SO₂ is the injection of this materialinto H₂S-containing, depleted, sour-gas reservoirs.

Since many reservoirs containing substantial quantities of H₂S alsocontain substantial quantities of desirable hydrocarbon materials whichit is desired to produce, it would be desirable if a method could befound to reduce the amount of H₂S in such reservoirs and in the producedmaterials before bringing them to the surface.

Accordingly a considerable effort has been directed to the developmentof a method whereby the H₂S content of a subterranean formation and ofproduced materials from such a formation, such as crude oil, lighthydrocarbon liquids, hydrocarbon gases and the like, could be reducedprior to bringing these materials to the surface.

SUMMARY OF THE INVENTION

The invention comprises a method for reducing the hydrogen sulfidecontent of fluids produced from a hydrogen sulfide-containingsubterranean formation, the method comprising: providing a supply ofsulfur dioxide at an injection site for the subterranean formation;injecting the sulfur dioxide into the subterranean formation; and,recovering fluids having reduced hydrogen sulfide content from thesubterranean formation.

The invention also comprises a method for reducing the hydrogen sulfidecontent of a hydrogen sulfide-containing subterranean formation, themethod comprising: providing a supply of sulfur dioxide at an injectionsite for the subterranean formation; and, injecting the sulfur dioxideinto the subterranean formation.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic diagram of an embodiment of the present invention;and,

FIG. 2 is a graph showing the projected reduction in H₂S in asubterranean formation during the injection of SO₂;

FIG. 3 is a schematic diagram of two wellbores positioned to penetrate asubterranean formation;

FIG. 4 is a top view of a typical five spot injection and productionarrangement of oil wells; and,

FIG. 5 is a further top view of an embodiment of an oil field whereinfive spot arrangements are used in combination to produce fluids fromthe field.

DESCRIPTION OF PREFERRED EMBODIMENTS

In the discussion of the Figures, numerous valves, heat exchangers, andthe like required to achieve the process flows shown have not been shownin the interest of simplicity since such equipment is well known tothose skilled in the art.

in FIG. 1 a representative process is shown for the production of SO₂for injection into a subterranean formation containing H₂S. In theprocess shown schematically in FIG. 1, a production well 10 is shownextending from an earth surface 12 into a subterranean formation 13containing H₂S and producing gas. Sour gas is recovered through a line14 and passed to a gas treatment facility 16 where the H₂S is removed,along with other materials such as carbon dioxide, condensable gases andthe like, as known to those skilled in the art. The sweet gas is thenpassed through a line 18 as a product to a pipeline or the like. The H₂Sis recovered through a line 20 and passed to a Claus sulfur recoveryunit 22. Such units, as well known to those skilled in the art, are ableto convert acid gas streams containing H₂S and other constituents, suchas hydrocarbons and the like into sulfur by the reactions discussedpreviously.

In the process shown, the off gases are recovered through a line 26 as aClaus tail gas stream passed to a tail gas unit 28 and treated to enablethe venting of the tail gases through a line 30 to the atmosphere. Suchprocesses are well known to those skilled in the art. A sulfur steam 24is recovered from Claus unit 22 and passed to sulfur combustion in asulfur combustor 32. The resulting SO₂ stream is passed through a line32 to a waste heat recovery section 36 where heat is recovered, forinstance as steam, which is passed via line 38 to a steam turbine 40,which drives a generator 42 for the production of electrical power. Thecooled SO₂ is then passed via line 44 to a SO₂ liquefaction section 46where it is liquefied with the production of additional low grade steamthrough a line 48, which could be used for a variety of purposes, suchas salt water desalinization 50 or the like. The resulting liquefiedsulfur is recovered through a line 52 and pumped by a pump 54 through aline 56 to an injection well 58.

The SO₂ is desirably injected on a continuous or intermittent long-termbasis. In FIG. 2, the reduction of the H₂S in a formation is shown. Inthe formation shown, the calculations of the results are based upon therecovery of gas containing H₂S from a ten-trillion cubic foot reservoirat a six hundred million standard cubic foot per day gas extraction ratewith the recovered sulfur being injected as SO₂. After ten years, theH₂S in the formation has been reduced from about 36 percent initially toabout 24 percent. This reduction is accomplished by simply returning theSO₂ produced by processing the H₂S removed from the formation andreturning it to the formation as SO₂ at an injection well. Desirablywell 10 is periodically tested to determine when and whether an SO₂breakthrough has occurred. The injection of SO₂ can be stopped when theproducts contain levels of SO₂.

In FIG. 3, a well 200 is shown extending from an earth surface 202through an overburden 204 into a formation 206. Well 200 comprises awellbore 212, which includes a casing 208 which is cemented in place bycement 210. The bottom of the well is shown at 214 near the bottom offormation 206. A tubing 216 is positioned to extend from formation 206to the surface for the production of fluids. The production of fluidsfrom tubing 216 is shown by arrow 228. A packer 218 is positionedbetween the outside of tubing 216 and the inside of casing 208 toprevent the flow of fluids upwardly between the outside of tubing 216and the inside of casing 208. Such techniques are well known to thoseskilled in the art and will not be further discussed. Perforations 220are shown into formation 206 for the production or injection of fluidsinto formation 206. In well 200, the production of fluid is shown byarrows 224 to indicate the production of fluids into well 200.

A second well 200′ is shown and includes the same components as well200, with substantially the same components being indicated by primenumbers corresponding to the numbers in well 200. The exceptions arethat the injection of sulfur dioxide is shown via an arrow 226, downtubing 216′ and injection is shown by arrows 222 into formation 206through perforations 220′. In the operation of the wells to injectsulfur dioxide into the formation, the sulfur dioxide may be injected atany suitable pressure alone or with a second fluid, which could be amaterial such as nitrogen, carbon dioxide, water or the like to reactwith hydrogen sulfide in formation 206 to reduce the concentration ofthe hydrogen sulfide in formation 206 and in the fluids produced throughwell 200. Clearly the wells are not shown at a spacing to scale,

In the practice of the present invention to inject sulfur dioxide into asubterranean formation to reduce the hydrogen sulfide content of theformation, a pattern such as shown in FIG. 4, which is commonly referredto as a five spot pattern, may be used. Wells 230, 232, 234, and 236 areproduction wells with the injection of a production enhancing materialbeing made through a central well 238. In such an embodiment sulfurdioxide, optionally with an additional fluid may be introduced into well238 and as production begins and continues is drawn outwardly towardwells 230, 232, 234, and 236.

In FIG. 5 a further embodiment of a well pattern is shown. In thisinstance, two five spot patterns are shown together and it will beappreciated by those skilled in the art that this pattern could berepeated over and entire field. In such instances the injected materialmay be used to drive gas or other desired materials toward productionwells, which include not only 230, 232, 234, and 236 but also 240 and242, with injection being through wells 244 and 238.

The use of materials to push desired fluids, such as hydrocarbons or thelike, from a subterranean formation is well known and may be practicedin combination with the injection of the SO₂. The sulfur dioxide asproduced above is usable for injection without the purification requiredwhen pure sulfur dioxide is desired. For instance, the stream producedthrough line 56 is frequently of adequate purity for use for thispurpose.

Accordingly, when processes, such as discussed above are available, theproduced sulfur as well as available additional sulfur dioxide may beused to reduce the amount of H₂S in the formation.

While a representative process has been shown utilizing a Claus processand sulfur oxidation, it is well known that SO₂ may be produced oravailable from a variety of sources. Any such source is considered to besuitable for use for this purpose. Further, while the process shown inFIG. 1 utilizes the recovery of sour gas it is clear that the process ofthe present invention is also useful when materials such as crude oilsor light hydrocarbons, such as condensates, are produced. The sulfurrecovery may be at a remote location in this instance since the oilswill be refined at a refinery location. Typically such crude oils may betreated for the removal of readily removeable H₂S at the productionsite. Such H₂S can be converted to SO₂ and re-injected. Alternativelyother sources of SO₂ may be used.

As noted previously it has been proposed in the past to dispose ofunwanted SO₂ and SO₂ and carbon dioxide mixtures, as well as mixtureswith other gases, into spent subterranean formations which areconsidered capable to contain the undesired gases. The use of suchdepleted formations for the storage of waste gases is not considered toshow or suggest to those skilled in the art the present invention, whichis directed to the use of SO₂ to remove H₂S from a formation and toremove H₂S from products recovered from the formation.

While the present invention has been described by reference to certainof its preferred embodiments, it is pointed out that the embodimentsdescribed are illustrative rather than limiting in nature and that manyvariations and modifications are possible within the scope of thepresent invention. Many such variations and modifications may beconsidered obvious and desirable by those skilled in the art based upona review of the foregoing description of preferred embodiments.

1. A method for reducing the hydrogen sulfide content of a hydrogensulfide-containing subterranean formation and providing energy, themethod consisting essentially of: a) providing a supply of sulfurdioxide at an injection site for the subterranean formation; b)injecting the sulfur dioxide into the subterranean formation; and, c)recovering a product stream from the subterranean formation.
 2. Themethod of claim 1 wherein the injection site comprises an injection wellextending from an earth surface into the subterranean formation.
 3. Themethod of claim 1 wherein the sulfur dioxide is passed through at leasta portion of the subterranean formation.
 4. The method of claim 1wherein at least a portion of the hydrogen sulfide is reacted with thesulfur dioxide in situ in the subterranean formation to produce sulfur.5. The method of claim 1 wherein at least a portion of the sulfurdioxide injected is produced from hydrogen sulfide recovered from atleast one product stream from the subterranean formation. gas.
 6. Themethod of claim 5 wherein the product stream comprises a hydrocarbongas.
 7. The method of claim 5 wherein the product stream comprises crudeoil.
 8. The method of claim 5 wherein the product stream comprises alight hydrocarbon liquid.
 9. A method for reducing the hydrogen sulfidecontent of fluids produced from an hydrogen sulfide-containingsubterranean formation, the method comprising: a) providing a supply ofsulfur dioxide at an injection site for the subterranean formation; b)injecting the sulfur dioxide into the subterranean formation; and c)recovering fluids having a reduced hydrogen sulfide content from thesubterranean formation.
 10. The method of claim 9 wherein the injectionsite is an injection well extending from an ear surface into thesubterranean formation.
 11. The method of claim 9 wherein the fluid isat least one of a gas, a liquid or a mixture thereof.
 12. The method ofclaim 9 wherein the sulfur dioxide is injected alone or with a drivefluid.
 13. The method of claim 9 wherein sulfur dioxide injection isstopped when sulfur dioxide is present in the recovered fluids.